Rigless method to partially lift or retrieve wellbore tubing strings from platform and subsea wells

ABSTRACT

A method for lifting a tubular string from a wellbore includes cutting the tubular string at a selected depth in the wellbore. A check valve is disposed in the tubular string above the selected depth. An interior of the tubular string is pressurized with gas to displace liquid in the tubing through the check valve. The tubular string is lifted, and a portion of the tubular string extending out of the wellbore is cut.

CROSS REFERENCE TO RELATED APPLICATIONS

Continuation of International Application No. PCT/IB2021/057683 filed on Aug. 20, 2021. Priority is claimed from U.S. Provisional Application No. 63/074,044 filed on Sep. 3, 2020, which application is incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable

NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT

Not Applicable.

BACKGROUND

This disclosure relates to the field of plugging and abandonment of underground wells, such as oil and gas producing wellbores. More particularly, the disclosure relate to a method for rigless complete or partial retrieval of well conduit such as production tubing strings, even when a wellhead is located on the bottom of a body of water (e.g., the seabed).

When underground (subsurface) wells are to be permanently abandoned, it is common to retrieve and discharge certain conduit, e.g., production tubing string(s) from the wellbore as part of the abandonment procedure. Removing conduit is typically performed using a conduit hoisting and handling apparatus, e.g., a drilling rig. There are a number of technologies being developed with the target of permanently leaving the conduit such as tubing string(s) in the wellbore, but in any event an upper section of the tubing string(s) need to be retrieved to establish a so-called environmental barrier which is placed near the top of the wellbore. In addition, to leave the tubing string(s) in the wellbore, it is necessary to ensure that a barrier, typically cement placed outside an outermost well conduit (casing) when the well was constructed, has a pressure sealing capability. To verify such capability, various wireline logging tools that can be deployed to the required depth and interval in the well. A commonly known tool is the so-called “Cement Bond Logging” tool. A challenge is that the tubing string(s) must generally be removed from the well to use such tools for evaluating the quality of cement outside the casing. Aarbakke Innovation AS, Bryne, Norway provides a wireline tool system referred to as the Tubular Slicer, which is an alternative for wells having only one tubing string installed. However, this technology is not suitable for dual tubing string type wellbores. Hence, and due to the need for an alternative to this Tubular Slicer, there is a requirement for a technology to remove a required length of tubing string(s) to be able to perform the logging.

SUMMARY

One aspect of the present disclosure is a method for lifting a tubular string from a wellbore. A method according to this aspect includes cutting the tubular string at a selected depth in the wellbore. A check valve is disposed in the tubular string above the selected depth. An interior of the tubular string is pressurized with gas to displace liquid in the tubing through the check valve. The tubular string is lifted, and a portion of the tubular string extending out of the wellbore is cut.

Some embodiments further comprise placing a barrier material in the tubular string below the selected depth prior to cutting the tubular string at the selected depth.

Some embodiments further comprise removing the check valve and lowering a well logging tool through the tubular string into a space below a bottom end of the lifted tubular string.

In some embodiments, the well logging tool comprises a cement evaluation tool, the method further comprising operating the cement evaluation tool to determine integrity of a cement barrier between a wall of the wellbore and a casing disposed in the wellbore.

Some embodiments further comprise removing the check valve and moving a barrier material into the wellbore through the lifted tubular string.

Some embodiments comprise sealing an annular space between the tubular string and the wellbore proximate a surface end of the wellbore, and pressurizing the annular space.

In some embodiments, the lifting and cutting are performed proximate a surface end of the wellbore.

In some embodiments, the cutting is performed proximate a bottom of a body of water.

Some embodiments further comprise affixing at least one buoyancy device to the tubular string, and using a vessel on a surface of the body of water to move the tubular string away from the wellbore.

Some embodiments further comprise lowering the tubular string into the wellbore after the cutting the portion extending from the wellbore.

Some embodiments further comprise repeating the lifting the tubular string and cutting the portion extending from the wellbore until a selected amount of the tubular string has been cut.

A method for lifting a tubular string from a wellbore according to another aspect of the present disclosure includes cutting the tubular string at a selected depth in the wellbore. A check valve/anchor combination is disposed in the tubular string above the selected depth. An interior of the tubular string is pressurized with gas to displace liquid in the tubing through the check valve. An anchor portion of the combination is set by further pressurizing the interior of the tubular string.

Some embodiments further comprise inserting a well logging tool into a space below the anchor portion to evaluate the wellbore below a bottom of the tubular string.

Other aspects and possible advantages will be apparent from the description and claims that follow.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a wellbore having two production tubing strings placed within a production casing.

FIG. 2 illustrates that an additional barrier, not necessary for the invention to work, is placed above the packer.

FIG. 3 illustrates that the tubing strings are severed, e.g. by a wireline tubular cutting tool, at the deepest depth of wellbore section of interest to be logged.

FIG. 4 illustrates that a wireline deployed check valve is installed within the tubing above the area this tubing was cut.

FIG. 5 illustrates that compressed air is pumped into the tubing strings through a packoff system temporarily locked into the top of the tubing strings.

FIG. 6 is a simplified illustration of the equipment used at the surface (or subsea) to lift and cut segments of tubing.

FIG. 7 illustrates that a tubular cutting device has severed the tubing strings.

FIG. 8 illustrates how one or several tubing strings can be retrieved up to a predetermined depth, providing a “window” where tubing strings are not present.

FIG. 9 illustrates that one of the check valves is removed, and that a logging tool is deployed to required depth.

FIG. 10 illustrates that the barrier integrity survey concluded that no repairs are needed, and that the tubing strings are cut and dropped into the wellbore.

FIG. 11 illustrates how tubing strings may be retrieved from seabed located wellbores using a surface floating structure, as for example a vessel.

FIG. 12 illustrates how a retrieved tubing string can be delivered from a tubing pulling vessel to another handling and transport vessel.

FIG. 13 illustrates how a tubing string may be prepared for transport to shore or other location.

DETAILED DESCRIPTION

This disclosure sets forth a method for retrieving one or several tubular strings, e.g., production tubing, from a wellbore using compressed gas or air in combination with a pulling or lifting mechanism at the surface. As a general overall description of such method, first, the tubular strings are cut, severed or separated at a selected depth in the wellbore. Such depth may be below a lowest depth in the wellbore to be evaluated for mechanical and/or hydraulic integrity in advance of abandonment. Thereafter, the compressed gas or air is pumped into the tubular strings from proximate the surface, for example, by the use of a pack-off or annular seal placed into the top end of the tubular string(s). The compressed gas or air displaces liquid in the tubular string(s). This fluid displacement by air or gas may be obtained by placing a check valve near the lower end of the tubular string(s) just above the separation depth, allowing flow-through from above, and allowing the liquid inside the tubular string(s) to exit through the check valve to the part of the wellbore below the check valve. The check valve prevents liquid reentry into the tubular strings after the gas or air pressure is relieved, thereby enabling further operations on the tubing strings. The liquid displacement will increase buoyancy in the tubular strings. The amount of buoyancy can be controlled by controlling the length of the air or gas column in the tubular string(s), that is, an amount of liquid in the tubular string(s) that is displaced by gas or air may be chosen or controlled to provide a predetermined amount of buoyancy. The result is substantially less effective weight of the tubular strings to be lifted and retrieved, and therefore reduces the required lifting capacity of a surface-deployed hoist or lift. To control the extraction of the tubular string(s) from the wellbore, a drive mechanism can be disposed at the surface to provide the required braking and pulling forces on the tubular strings. Using the combination of the tubular buoyancy induced by fluid displacement, the surface drive mechanism, and in addition a tubular cutting mechanism, wellbore tubular strings can quickly be retrieved from the wellbore without the need for a costly high capacity hoisting apparatus such as a drilling rig or workover rig. In the unlikely event of an unstable well, with associated risk of fluid inflow from a subsurface reservoir, it is fully feasible to implement a blow-out preventer system (BOP) below the surface-deployed drive mechanism and above the top of the wellbore to control possible well pressure events. The BOP may be activated to seal the wellbore and tubular strings to fluid flow. The BOP may be coupled to a pump in order to be able to move heavy kill fluid into the tubular string(s) and the wellbore in such event. Although the present disclosure sets forth a method for pulling tubular strings from wells having surface wellheads, it is within the scope of this disclosure to adapt the method to be performed from a vessel if marine (subsea) wells are to be abandoned, in which the respective wellhead may be located on the water bottom.

FIG. 1 illustrates an example embodiment of a wellbore 10 that may be operated upon using a method according to the present disclosure. The wellbore 10 may have two production tubing strings 12A, 12B placed within a production casing 14. The casing 14 provides a fluid barrier between rock formations (not shown) penetrated by and located outside the wellbore 10, and provides mechanical integrity to the wellbore 10. Near the lower end of the tubing strings 12A, 12B, an annular seal 15 such as a production packer supports the tubing strings 12A, 12B in the casing 14 and provides an additional barrier against the rock formations (not shown, called the “reservoir” in a fluid producing well). For permanent well abandonment procedures, there may be one or several permanent barriers against the reservoir (not shown) placed at or below the production packer 15 depth(s). The wellbore 10 may be liquid filled, with, for example, brine, seawater, drilling mud and/or similar liquids, where the hydrostatic pressure of the liquid provides an additional barrier against the reservoirs. At this point in the procedure, tasks to be performed do not necessarily require any additional pressure control systems proximate to or at the top of the wellbore 10. Note that the illustrations and description herein relate to two tubing strings in a wellbore, but those skilled in the art will understand that methods according to the present disclosure can also be used if there are more or fewer tubing strings in a particular wellbore. It is also within the scope of the present disclosure for any particular wellbore to be completed in “open hole”, wherein no production casing or liner is present.

In order to better understand a method according to the present disclosure, some example tubing string weights will be explained. If seawater (specific gravity about 1.01) is the liquid filling the tubing strings 12A, 12B, using an industry standard 3-½″ OD tubing string, such weights calculate as follows. A string of such tubing suspended in air weighs approximately 15.2 kilograms per meter (depending on tubing weight class). When disposed in water, the same tubing weighs approximately 9 kilograms per meter, if filled with air as described herein. If the same tubing string is disposed in drilling mud having specific gravity of 1.6, the weight per meter is approximately 5.3 kilograms. If the liquid in which the tubing is suspended were typical wellbore construction cement, the weight per meter of the tubing would be approximately 0.3 kilograms per meter. For example tubing string lengths of 1600 meters of the foregoing tubing, weights are:

Seawater filled, retrieved from a seawater filled wellbore=24,320 kg Air filled, retrieved from a seawater filled wellbore=14,400 kg Air filled, retrieved from a drilling mud filled wellbore=8,480 kg

As will therefore be appreciated, the effective weight of a tubing string to be retrieved from a wellbore can be significantly lowered by filling it with air or gas. Reducing the suspended weight of the tubing string(s) may provide substantial cost saving by reducing the required load capacity of a surface hoisting system.

FIG. 2 illustrates that an optional additional fluid barrier, in the form of a barrier material 16, e.g., cement, may be placed within each of the tubing strings 12A, 12B above the packer (15 in FIG. 1 ). A plug 18, for example, a wireline or slickline deployed plug, is placed in each of the tubing strings 12A, 12B first, to support the barrier material 16 until the barrier material 16 has hardened. The manner of placing the barrier material 16 is not described herein, but those skilled in the art will readily appreciate that various methods may be used to place the barrier material 16 as shown without the need to use a drilling rig or similar hoisting apparatus. FIG. 2 also shows that the barrier material 16 may be placed in an annular space 20 within the casing 14 and outside the tubing strings 12A, 12B.

FIG. 3 illustrates that the tubing strings 12A, 12B are severed, e.g., by a wireline or slickline deployed tubular cutting tool, at a depth in the wellbore section of interest. The cutting tool (not shown) may be, for example and without limitation, a jet cutter, chemical cutter, abrasive cutter and/or mill. The places where the tubing strings 12A, 12B are cut are shown at 27. To the extent the annular space 20 is not filled with liquid to a selected elevation, e.g., to the surface or a chosen depth below the surface, the annular space 20 may then be so filled, in some embodiments by pumping liquid from surface into the cut tubing strings 12A, 12B.

FIG. 4 illustrates that a check valve 22, which may be deployed, for example, by coiled tubing, wireline or slickline, is installed within each tubing string 12A, 12B above the depth at which the tubing string 12A, 12B was previously cut. The function of the check valves 22 is to allow liquid to be discharged from the interior of each tubing string 12A, 12B through the check valve(s) 22 to an area 23 below the tubing string(s) 12A, 12B while preventing fluid from such area 23 to flow back into the tubing strings 12A, 12B from below. Using such check valves 22 it is possible to control the amount of liquid displaced from the tubing string(s) 12A, 12B.

FIG. 5 shows compressed gas 25, e.g., air, being pumped into the tubing strings 12A, 12B through a respective packoff system E1 and E2. The packoff systems E1, E2 may be temporarily locked into each of the tubing strings 12A, 12B proximate the top thereof so that gas pressure can build inside each tubing string 12A, 12B. Pumping gas into the tubing strings 12A, 12B displaces liquid in the tubing strings 12A, 12B through the respective check valves 22, thereby lowering the effective weight of the tubing strings 12A, 12B.

In some embodiments, an annular seal may be installed proximate the surface between the tubing strings 12A, 12B and the casing 14, or a riser in marine well operations. Because a barrier has been placed in the wellbore below the cut ends of the tubing strings 12A, 12B, by pumping pressurized fluid into the tubing string(s) 12A, 12B from the surface, fluid displaced from the tubing strings 12A, 12B through the check valves 22 will pressurize the annular space (20 in FIG. 2 ). As the pressure in the annular space (20 in FIG. 2 ) increases, such pressure will act on the tubing strings 12A, 12B to urge them upwardly out of the wellbore (10 in FIG. 1 ). This additional upward push can be used in conjunction with or as an alternative to displacing liquid in the tubing strings 12A, 12B with air or gas. Not only may the requirements for lifting force on the tubing strings 12A, 12B be reduced to move them out of the wellbore for further operation, the additional forces may be beneficial in the event if one or more tubing strings become stuck in the wellbore, thereby requiring additional lifting force.

In some embodiments, the check valve 22 may be substituted by a combination check valve/tubing anchor. In such embodiments, after the tubing string(s), e.g., 12A and or 12B is severed at the selected depth, such combination check valve/anchor may be deployed in the tubing string(s) as explained with reference to FIG. 4 , and gas or air may be pumped into the tubing string(s) as explained with reference to FIG. 5 . As the suspended tubing string weight decreases, the length of the tubing string will decrease as a result of the reduction in suspended weight. At a selected gas pressure, the anchor part of the combination check valve/anchor will deploy against the interior of the casing 14. The free end of the tubing string(s) will then be prevented from moving downward in the casing 14. The gas pressure in the tubing string(s) may then be removed, the check valve part of the combination check valve/anchor may then be removed and a window, similar to that to be explained with reference to FIG. 8 will be opened in the casing 14 for subsequent operations.

FIG. 6 is a simplified illustration of hoisting equipment 30 that may be deployed at the surface (or proximate the water bottom for marine wells), consisting of a support frame 32 disposed over the wellbore (10 in FIG. 2 ), a drive mechanism 36, e.g., a tractor drive which may be similar to a tractor drive used to move coiled tubing and a winch 34 disposed in the support frame 32 to move tubulars up or down, and a tubular cutting tool 38. A tubing hanger 33 may be applied to the tubing strings 12A, 12B at a chosen axial position as shown in FIG. 6 . The tubing strings 12A, 12B are lifted by the drive mechanism 36. The winch 34 may also act to lift the tubing hanger 33 to assist in lifting the tubular strings 12A, 12B. Once the tubing strings 12A, 12B are lifted to a selected elevation, the drive mechanism 36 is stopped.

FIG. 7 shows that the tubular strings have been severed by the cutting device 38.

The ends of the tubing strings, shown at 12A-1 and 12B-1 above the respective cuts as suspended by the winch 34 cooperatively acting with the tubing hanger 33. The ends 12A-1, 12B-1 may be moved from above the wellbore by a line 31 and subsequently lowered and removed from the work area for transport and disposal. The sequence of actions of FIG. 6 and FIG. 7 may be repeated for any selected number of repetitions until a desired amount of the tubing strings 12A, 12B is removed from the wellbore. As will be further explained below, only a limited length of the tubular strings 12A, 12B may be removed from the wellbore, and the remaining part of the tubular strings 12A, 12B may be allowed to drop in the wellbore for subsequent abandonment.

It will be appreciated that as a result of the reduced effective weight of the tubing strings 12A, 12B obtained by displacing liquid therein with gas as previously explained, the load capacity of the support frame 32, the drive mechanism 36 and the winch 34 may be substantially reduced from what would be required to lift the entire weight of a corresponding length of tubular string unsupported by any buoyancy.

FIG. 8 shows that after the tubing strings 12A, 12B are cut, they may be lifted, e.g., using the lifting apparatus explained with reference to FIGS. 6 and 7 , by a selected axial distance to open a “window” 50 in the wellbore where tubing strings are not present inside the casing 14. The window 50 length would be determined by the distance required for a logging tool system to provide sufficient measurements about barrier integrity externally of the casing 14, as will be further explained with reference to FIG. 9 .

FIG. 9 illustrates that one of the check valves 22 may be removed after the corresponding tubing string (e.g., 12A) is once again filled with liquid. A well logging tool 60 may be deployed through the open tubing string 12A, for example, by electrical cable 62, slickline or coiled tubing to a required depth. For example the well logging tool may be deployed into the window 50 for evaluation of the barrier (e.g., cement) outside the casing 14. The well logging tool 60 may be, for example an acoustic-based cement evaluation tool of types known in the art. The well logging tool 60 may obtain information such that the well operator can determine whether the barrier outside the casing 14 has sufficient integrity to abandon the wellbore 10.

In FIG. 10 , after the barrier integrity survey using the well logging tool (FIG. 9 ) is concluded, and the result is that no repairs are needed to the casing 14 or its external barrier, the tubing strings 12A, 12B may be cut at a convenient axial location, and dropped or lowered in a controlled manner into the wellbore 10. If a repair to the casing 14 is required, such repair operation may be performed prior to cutting and dropping the tubing string(s) 12A, 12B, depending on the nature of the repair required, when in appropriate circumstances it is possible to perform such repair through the tubing string(s) 12A, 12B. Following lowering the tubing strings 12A, 12B, a plug, e.g., a wireline or slickline set plug 17 may be set in the casing 14 above the dropped tubing strings 12A, 12B. Then more barrier material 16 may be dumped into the wellbore 10 above the plug 17. Finally, a so-called environmental barrier may be placed in the upper end of the wellbore 10, in close proximity to the seabed or ground surface.

FIG. 11 illustrates how a tubing string 12 may be retrieved from a marine (seabed) wellbore 10A using a surface floating structure, as for example, a tubing retrieval vessel 70. Parts of a method as explained with reference to FIGS. 2 through 5 , wherein a check valve (22 in FIG. 3 ) is set in the tubing string 12 and air or gas is pumped to displace liquid in the tubing string 12 may be performed in connection with the present example embodiment to reduce the weight of the tubing string 12 suspended in a body of water 776 such as a lake or the ocean.

A wellhead, which would ordinarily be coupled to the top of the wellbore 10A is not illustrated in FIG. 11 for clarity, but those skilled in the art will understand that such a wellhead is generally present below a BOP system 78 as illustrated. At the water bottom or seabed 71, the BOP system 78 may be closed to fluid flow. Such closure may comprise operating seal elements, such as pipe rams, blind rams and/or annular seals. The B OP system 78 may comprise one or more fluid feedthroughs 78A, where fluids may be injected into the wellbore below the BOP system 78. Such fluid injection may be required, for example, to change out wellbore fluid to that of a different density, etc. Fluid transport into the wellbore 10A may be performed using a flexible tube (not shown) extended from the surface vessel 70. Above the BOP system 78, a drive mechanism 76 may be attached to assist tubing retrieval from the wellbore 10A. The drive mechanism 76 may be similar in structure and function to tubing drive mechanisms used, for example, in inserting and retrieving continuous coiled tubing in a well. A tubing cutting device 74 may be disposed above the BOP system 78 to sever the tubing string 12 as needed during recovery and abandonment operations.

The tubing retrieval vessel 70 may also, or instead of the drive mechanism 76, have a winch or other lifting system on board that is capable of lifting the tubing string 12 out of the wellbore. The vessel-borne lifting system may comprise a tubing hanger/clamp 72 to attach to the upper end of the tubing string 12 for lifting purposes. When a particular length of the tubing string 12 is lifted from the wellbore 10A, which could be, for example, approximately equal to water depth, the cutting device 78 may be operated to cut the portion of the tubing string 12 extending from the BOP system 78 to the vessel 70 (at the tubing hanger/clamp 72).

In the present example embodiment, the tubing string 10A may be severed above at a selected depth below the water bottom as explained with reference to FIG. 3 . A check valve (see FIG. 4 ) may be set in the tubing string 10A above the severance depth. Air or gas may be pumped into the tubing string 10A to displace liquid therein, so as to reduce the effective weight of the tubing string in the water 71. The tubing retrieval vessel 70 may operate the winch to retract the tubing hanger/clamp 72, and/or the drive mechanism 76 may be operated to lift the severed tubing 12 from the wellbore. The BOP system 78 may be opened to enable lifting the severed tubing and subsequently closed once again. The cutting device 74 may be operated to sever the length of the tubing string 12 suspended in the water from the tubing retrieval vessel 70. The foregoing procedure may be repeated until a desired amount of the tubing string 12 is lifted from the wellbore 10A, or the remaining tubing string 12 may be lowered or dropped into the wellbore 10A for later plugging and abandonment as explained with reference to FIG. 10 .

FIG. 12 illustrates how a retrieved (severed as explained with reference to FIG.

11) portion of the tubing string 12 can be delivered from the tubing retrieval vessel 70 to a handling and transport vessel 73. The handling and transport vessel 73 may be connected to the tubing hanger/clamp 72 using a lifting wire 75 deployed from the handling and transport vessel 75. Thereafter, the tubing retrieval vessel 70 disconnects its winch from the tubing hanger/clamp 72, allowing the handling and transport vessel 73 to pull the tubing string 12 away from the tubing retrieval vessel 70. At the same time, the tubing retrieval vessel 70 deploys a new tubing hanger/clamp 72A by wire 77 down to the tubing cutting system (74 in FIG. 11 ). A guide wire system, or a thruster arrangement may be connected to the new tubing hanger/clamp 72A to assist in this deployment and the delivery of the new tubing hanger/clamp 72A to the location of the cutting system. (74 in FIG. 11 ).

FIG. 13 illustrates how a severed section of tubing string 12, recovered as explained with reference to FIGS. 11 and 12 and moved using the transport and recovery vessel 73 may be prepared for transport to shore or other location. The severed tubing string section 12 is suspended near the water surface using any form of buoyancy elements 79 connected to the tubing string 12. Installing a check valve into the lower end of the tubing string first, followed by a similar installation in the top of the tubing, e.g., by wireline, allows compressed air or gas to be pumped into the tubing string 12 to displace the seawater or other liquid within. This reduces the weight of the tubing string 12. A number of individual tubing strings may be held at or close to the water surface using this method, where the tubing string sections then may be towed to shore or pulled onto the transport and recovery vessel 73 and cut into suitable lengths.

In light of the principles and example embodiments described and illustrated herein, it will be recognized that the example embodiments can be modified in arrangement and detail without departing from such principles. The foregoing discussion has focused on specific embodiments, but other configurations are also contemplated. In particular, even though expressions such as in “an embodiment,” or the like are used herein, these phrases are meant to generally reference embodiment possibilities, and are not intended to limit the disclosure to particular embodiment configurations. As used herein, these terms may reference the same or different embodiments that are combinable into other embodiments. As a rule, any embodiment referenced herein is freely combinable with any one or more of the other embodiments referenced herein, and any number of features of different embodiments are combinable with one another, unless indicated otherwise. Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible within the scope of the described examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. 

What is claimed is:
 1. A method for lifting a tubular string from a wellbore, comprising: cutting the tubular string at a selected depth in the wellbore; disposing a check valve in the tubular string above the selected depth; pressurizing an interior of the tubular string with gas to displace liquid in the tubing through the check valve; lifting a part of the tubular string above the selected depth; cutting a portion of the lifted part of the tubular string extending out of the wellbore; removing the check valve; and lowering a well logging tool through the lifted part of the tubular string into a space below the bottom end of the lifted tubular string.
 2. The method of claim 1 further comprising placing a barrier material in the tubular string below the selected depth prior to cutting the tubular string at the selected depth.
 3. The method of claim 1 wherein the well logging tool comprises a cement evaluation tool, the method further comprising operating the cement evaluation tool to determine integrity of a cement barrier between a wall of the wellbore and a casing disposed in the wellbore.
 4. The method of claim 1 further comprising removing the check valve and moving a barrier material into the wellbore through the lifted portion of the tubular string.
 5. The method of claim 1 further comprising sealing an annular space between the tubular string and the wellbore proximate a surface end of the wellbore, and pressurizing the annular space.
 6. The method of claim 1 wherein the lifting and cutting are performed proximate a surface end of the wellbore.
 7. The method of claim 1 wherein the cutting is performed proximate a bottom of a body of water.
 8. The method of claim 7 further comprising affixing at least one buoyancy device to the tubular string, and using a vessel on a surface of the body of water to move the tubular string away from the wellbore.
 9. The method of claim 1 further comprising lowering the tubular string into the wellbore after the cutting the portion extending from the wellbore.
 10. The method of claim 1 further comprising repeating the lifting the tubular string and cutting the portion extending from the wellbore until a selected amount of the tubular string has been cut.
 11. The method of claim 1 further comprising cutting the lifted portion of the tubular string at a selected axial location and and dropping or lowering the cut, lifted tubular string in a controlled manner into the wellbore.
 12. A method for lifting a tubular string from a wellbore, comprising cutting the tubular string at a selected depth in the wellbore; disposing a check valve/anchor combination in the tubular string above the selected depth; pressurizing an interior of the tubular string with gas to displace liquid in the tubing through the check valve; and setting an anchor portion of the combination by further pressurizing the interior of the tubular string, the anchor setting against an interior of a well casing to anchor the tubular string in the well casing.
 13. The method of claim 12 further comprising inserting a well logging tool into a space below the anchor portion to evaluate the wellbore below a bottom of the tubular string. 